Apparatus and method for installing and removing well tools in a tubing string

ABSTRACT

A WELL TOOL SYSTEM FOR INSTALLING AND RETRIEVING WELL TOOLS, SUCH AS GAS LIFT VALVES, IN A TUBING STRING. A TUBULAR LATCH IS PROVIDED FOR LOCKING EACH WELL TOOL AT A LANDING NIPPLE IN THE TUBING STRING. THE LATCH HAS LOCKING KEYS WITH OPERATOR MEMBERS MANIPULATED RESPONSIVE TO A SUPPORTING PROBE FOR LOCKING AND RELEASING EACH LATCH AT A LANDING NIPPLE. ONE OR A PLURALITY OF THE LATCHES WITH CONNECTED WELL TOOLS ARE SUPPORTED ON THE PROBE IN TANDEM. THE PROBE AND SUPPORTED LATCHES AND WELL TOOLS ARE CONNECTED IN A TOOL TRAIN WHICH MAY INCLUDE WIRELINE OR PUMP DOWN HANDLING TOOLS WITH SLEEVE VALVE OPERATORS FOR OPENING AND CLOSING SLIDING SLEEVE VALVES AT THE LANDING NIPPLES WHEN INSTALLING AND REMOVING THE LATCHES AND WELL TOOLS. THE TOOL TRAIN IS RUN IN A TUBING STRING TO A DEPTH BELOW THE LOWEST LANDING NIPPLE AND IS THEN RETURNED TO THE SURFACE SEQUENTIALLY RELEASING AND LOCKING THE LATCHES AT THE LANDING NIPPLES SPACED ALONG THE TUBING STRING. THE LATCHES AND TOOLS ARE RETRIEVED BY RUNNING THE TOOL TRAIN WITH A PROBE DOWNWARDLY SEQUENTIALLY RELEASING THE LATCHES AND ENGAGING THEM ON THE PROBE IN END-TO-END ARRAY. WHEN ALL OF THE LATCHES AND WELL TOOLS ARE RELEASED AND ON THE PROBE, THE TOOL TRAIN IS RETURNED TO THE SURFACE. DURING BOTH INSTALLING AND REMOVING THE LATCHES AND TOOLS, THE SLEEVE SHIFTING UNITS IN THE TOOL TRAIN OPEN AND CLOSE THE SLEEVE VALVES AS REQUIRED.

p 21, 1971 H. E. SCHWEGMAN APPARATUS AND METHOD FOR INSTALLING ANDREMOVING WELL TOOLS IN A TUBING STRING Filed April 17, 1969 11Sheets-Sheet 1 INVENTOR. Harry E Schwegmun BY \4 .WbM

ATTORNEY P 1971 H. E. SCHWEGMAN 3,606,926

APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOQLS IN A TUBINGSTRING Filed April 17, 19653 M 11 Sheets-Sheet 2 .6]? 63/ 6'84 6 c 5%.L5 53! 6'82 0 64 e53 625 a 654 624 622 m; e45

6 see 9 693 F|g.3C U. 52 INVIiN'I'UR.

Harry E.Schwegmon ATTORNEY APPARATUS AND METHOD FOR INSTALLING AND P 21,1971 H. E. SCHWEGMAN 3,606,926

' REMOVING WELL TOOLS IN A TUBING STRING Filed April 17, 1969 llSheets-Sheet 5 INVENTOR. Harry E. Schwegmon AT'I 'ORNEY Sept. 21, H. E.SCH'WEGMAN -wrhmwus AND 14mm) FOR INSTALLING AND a vREMOVING WELL T001;18 A TUBING sums Filed April 17, 1363? A 11 Sheets-Sheet 4 INVENTOR.Harry E. Schwegmon BY ATTORNEY 11 Sheets-Sheet 5 Sept. 1971 H. E.SCHWEGMAN APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS INA TUBING STRING Filed April 17, 1969 n .G W mmM w Tg R mm w W.n M .IC 55 E 0 W H m m Fig. 6

Sept.- 21, 1971 H. E. SCHWEGMAN APPARATUS AND METHOD FOR INSTALLING ANDREMOVING WELL TOOLS IN A TUBING STRING ll Sheets-Sheet 6 Filed April17', 1969 3 M mm T 9 CHHM ATTORNEY Sept. 21, 1971 H. E. scHwEGMAN3,606,926

APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBINGSTRING Filed April 17, I969 l1 Sheets-Sheet '7 m 67m 6' a L 68/01 6I7Q/Fig. IO C Flg. K) B INVENTOR. l Harry E. Schwegmon BY \4 NwXsM Fig.lOA

ATTORNEY p 21, 1971 H. E. SCHWEGMAN 3,606,926

APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBINGSTRING Filed April 17, 1969 ll Sheets-Sheet 8 I l K ,vm 753 7;; \LJ WYFi .l 6I7J g 9 Fig.l6

v INVENTOR. 753 Harry E. Schwgman BY wW M Fig.,l8

ATTORNEY Sept. 21, 1971 H. E. 'SCHWEGMAN 3,606,926 APPARATUS AND METHODFOR INSTALLING AND REMOVING WELL TOOLS IN A TUBING STRING 11Sheets-Sheet 9 Filed April 17', 1969 INVENTOR. Harry E. Schwegmun BYFig.22

A T TORNEY Sept. 21, 1971 H. E. SCHWEGMAN APPARATUS AND METHOD FORINSTALLING AND 1 REMOVING WELL TOOLS IN A TUBING STRING Filed April 17,1969 ll Sheets-Sheet l0 INVENTOR. Hoqry E.Schwegmon BY \6 .WNZ} MATTORNEY Sept. 21, 1971 Filed April 17, 1969 H. E. SCHWEGMAN 3,606,926

APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBINGSTRING ll Sheets-Sheet 11 ATTORNEY United States Patent 3,606,926APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBINGSTRING Harry E. Schwegman, Plano, Tex., assignor to Otis EngineeringCorporation, Dallas, Tex.

Filed Apr. 17, 1969, Ser. No. 816,942

Int. Cl. E21b 23/02 US. Cl. 166315 54 Claims ABSTRACT OF THE DISCLOSUREA well tool system for installing and retrieving well tools, such as gaslift valves, in a tubing string. A tubular latch is provided for lockingeach well tool at a landing nipple in the tubing string. The latch haslocking keys with operator members manipulated responsive to asupporting probe for locking and releasing each latch at a landingnipple. One or a plurality of the latches with connected well tools aresupported on the probe in tandem. The probe and supported latches andwell tools are connected in a tool train which may include wireline orpumpdown handling tools with sleeve valve operators for opening andclosing sliding sleeve valves at the landing nipples when installing andremoving the latches and well tools. The tool train is run in a tubingstring to a depth below the lowest landing nipple and is then returnedto the surface sequentially releasing and locking the latches at thelanding nipples spaced along the tubing string. The latches and toolsare retrieved by running the tool train with a probe downwardlysequentially releasing the latches and engaging them on the probe inend-to-end array. When all of the latches and well tools are releasedand on the probe, the tool train is returned to the surface. During bothinstalling and removing the latches and too-ls, the

sleeve shifting units in the tool train open and close the sleeve valvesas required.

This invention relates to well tools and more specifically to a welltool system for installing and removing tools in a well tubing.

It is a particularly important object of the invention to provide a newand improved tool system for installing and removing well tools in welltubing.

It is another object of the invention to provide a well tool system ofthe character described which is operable by pumping techniques.

It is another object of the invention to provide a system and method forthe installation and removal of well tools in a well located remotelyfrom a surface installation as in the case of an off-shore underwaterwell connected with an on-shore surface well control and servicinginstallation.

It is another object of the invention to provide a system which permitswell tools to be pumped between a control station and locations'withinthe tubing of a well.

It is another object of the invention to provide a system for installingwell tools in a tubing string wherein each well tool, such as a gas liftvalve, is sequentially released and locked in the tubing as a string ofthe tools including apparatus for manipulating the tools in the tubingis pumped through the tubing.

It is another object of the invention to provide a method and apparatusfor the installation of well tools in a tubing wherein a string of welltools is pumped from the surface through the tubing to a depth belowthat at which one or more of the well tools is to be released and lockedin the tubing and the tool or tools are released and locked in thetubing during the return trip of the string of tools toward the surface.

It is another object of the invention to provide a well tool system ofthe character described wherein a string of tools is pumped throughtubing to a collar stop in the tubing below the locations at which thetools are to be released and locked in the tubing with the impact ofstriking the collar stop partially releasing or arming latches in thetool string for subsequent release from the string and locking in thetubing.

It is another object of the invention to provide a Well tool. system ofthe character described wherein the string of tools to be installed inthe tubing string is pumped only to a depth below the lowest location atwhich one or more of the tools is to be released and locked in thetubing.

It is a further object of the invention to provide a well tool system ofthe character described wherein the well tools supported in the toolstring are released and locked at desired locations in the tubing stringby manipulation of fluid pressure in the tubing.

It is a further object of the invention to provide a well tool system ofthe character described wherein a string of well tools is pumped throughthe well tubing to a depth below the location at which the lowermostwell tool is to be installed and the tool string is returned toward thesurface sequentially releasing and locking each well tool in the stringwith the supporting and motive means for the string of well tools beingreturned to the surface and removed from the well system.

It is a further object of the invention to provide a well tool system ofthe character described wherein the well tools are sequentially releasedfrom locking recesses in the well tubing, pumped down the tubing to stopmeans therein, secured on retrieving means, and pumped as a tool stringunit back to the surface.

It is another object of the invention to provide a well tool systemwhich includes a latch for releasably locking a well tool at a lockingrecess in well tubing, a running probe for supporting and installing thelatch in well tubing, and a pulling probe for releasing and removing thelatch from the well tubing.

It is another object of the invention to provide a well tool string forpumping through well tubing including a power piston, sleeve valveoperating means, and probe means for supporting one or more well toolsfor movement through the well tubing.

It is another object of the invention to provide a well tool system ofthe character described including releas able latch means adapted to bepumped with a well tool coupled thereto into well tubing, locked in thetubing,

subsequently released from the tubing, and pumped back to the surface inthe tubing.

It is a further object of the invention to provide a well tool system ofthe character described which includes a power piston for pumping a toolstring through a well tubing, a sleeve valve shifter for moving sleevevalves in well tubing from an upper to a lower position, a sleeve valveshifter for moving the sleeve valves back upwardly from the lowerposition, a running probe for supporting one or more well tools to bereleased and locked in the well tubing, and one or more latchessupportable on the probe to be released and locked in the well tubingfor supporting a well tool connected with each of the latches.

It is a further object of the invention to provide a Well tool system ofthe character described including a power piston, a sleeve valve shifterfor returning sleeve valves in a well tubing from a lower to an upperposition, and a pulling or retrieving probe for releasing, couplingwith, and retrieving well tools from the well tubing.

It is a still further object of the invention to provide a tool stringfor pumping well tools into well tubing and releasing and locking thetools in the tubing including a running probe adapted to release thewell tools supported on the probe responsive to a mechanical impactforce against a stop member in the well tubing.

It is another object of the invention to provide a well tool system ofthe character described including a running probe for supporting thewell tools including means for hydraulically releasing the well toolssupported on the probe at any desired depth in a well by manipulation offluid pressures in the well tubing.

It is a. further object of the invention to provide a well tool systemof the character described including a pulling probe for releasing andremoving the well tools from well tubing and including means for releaseof the probe from well tools which are stuck or jammed in the welltubing and thus cannot be removed by normal forces applicable throughthe probe.

It is a still further object of the invention to provide a latch forreleasably supporting well tools in a well tubing, the latch beingsupportable on a probe structure during installation and retrieval andbeing pumpable through the well tubing from a surface installation.

It is a further object of the invention to provide a well tool systemincluding tool strings for both installation of and removal of welltools such as strings being articulated to permit traverse of curvedtubing sections.

It is a further object of the invention to provide a well tool latch forreleasably locking a well tool in a tubing including expandable andcontractable locking keys movable by operator lugs and sleeve meansoperable responsive to positioning of a running or pulling probeinserted through a longitudinal central passage through the latch.

It is another object of the invention to provide a well tool latch forreleasably locking a well tool in a tubing, such latch having a fullbore opening throughout its length.

Additional objects and advantages of the invention will be readilyapparent from reading the following description of a device constructedin accordance with the invention and reference to the accompanyingdrawings where- FIG. 1 is a schematic view of a well system in which awell tool system embodying the invention is operable and showingparticularly a fragmentary longitudinal broken section of a cased wellhaving a well tubing system for manipulating the well tool system bypumpdown techniques;

FIG. 2 is a longitudinal view in elevation of a tool string embodyingthe invention for running-in or installing well tools by pumpdownprocedures;

FIGS. 3A-3E constitute a longitudinal view, partially in section, of thetool string including the running probe, latches, and gas lift valvesshown in FIG. 2 as the tool string is run into a well tubing;

FIG. 3A shows the head of the running probe and the upper end of theupper latch of the tool string;

FIG. 3B illustrates the lower end of the upper latch and the upper gaslift valve with its upper seal assembly;

FIG. 3C shows the lower seal assembly of the upper gas lift valve andthe upper portion of the lower latch in the tool string;

FIG. 3D shows the lower portion of the lower latch together with theupper seal assembly and an upper portion of the lower gas lift valve;

FIG. 3B illustrates a lower portion of the lower gas lift valve with itslower seal assembly and the lower end of the running probe together withthe bottom subassembly on the lower gas lift valve for coupling thetools and latches with the running and pulling probes;

FIG. 4 is a cross-sectional view taken along the line 44 of FIG. 3D;

FIG. 5 is an enlarged cross-sectional view of the upper latch mandrelhead and locking keys taken along the line 5-5 of the FIG. 3A;

FIG. 6 is an exploded perspective view partially broken away of themajor parts of the upper latch;

FIG. 7 is an enlarged cross-sectional view of the upper latch mandrelhead taken along the line 7--7 of FIG. 6;

FIG. 8 is a fragmentary view in longitudinal section and elevationshowing the lower end of the tool train and the running probe after thetrain has landed on a stop in the tubing to release the latches from therunning probe;

FIG. 8A is a fragmentary longitudinal view, partly in section, showingthe relative positions of the running probe, the locking keys and theoperating lugs of the lower latch when armed or partially released afterthe running probe engages the stop as represented in FIG. 8;

FIG. 9 is a view in section of the bottom stop along the line 99 of FIG.8;

FIGS. 10A through 10D comprise a longitudinal view, partly in section,of the tool string during a return trip in a tubing with the lower latcharmed for release and locking at a landing nipple;

FIG. 10A shows the head of the running probe with the upper end of theupper latch;

FIG. 10B illustrates intermediate and lower sections of the lower latchwith the locking keys expanded to the tubing wall as the latch movesupwardly toward a landing nipple in the tubing string;

FIG. shows the lower gas lift valve and its upper seal assembly inelevation;

FIG. 10D shows the lower end of the lower seal assembly of the lower gaslift valve and the bottom subassembly of the tool string for couplingthe string after the tool string and probe have landed at the bottomstop in the tubing and with the probe moved upwardly relative to thelatches and gas lift valve;

FIG. 11 is an enlarged fragmentary view, partly in section, showing therelative positions of the running probe with the latch locking keys andoperating lugs when the latch is locked at a landing nipple by itslocking keys expanded into the locking recesses of the landing nipple;

FIG. 12 is a view in section along the line 12-12 of FIG. 11;

FIG. 13 is a reduced longitudinal view in elevation of a tool stringincluding a pulling probe, a power piston unit, and a sliding sleevedownshift unit;

FIG. 14- is a fragmentary, longitudinal view partly in section of thelower end of the bottom subassembly of the lower gas lift valve and thelower end of the pulling probe as the pulling probe is initiallyinserted into the sub assembly;

FIG. 15 is a view similar to FIG. 14 as the pulling probe is liftedengaging the subassembly for raising the lower gas lift valve and latchin the tubing;

FIG. 16 is a fragmentary longitudinal view partly in section, of thelower end of a modified form of pulling probe when inserting the probeinto the bottom of a modified form of bottom subassembly adapted for usewith the modified probe;

FIG. 17 is a fragmentary longitudinal view partly in section, similar toFIG. 16 showing the pulling probe engaged in the subassembly for liftingthe assembly in the tubing;

FIG. 18 is a view similar to FIG. 17 showing the functioning of thereleasable feature of the modified pulling probe when the subassemblyand its related tools become jammed or lodged in the tubing string;

FIG. 19 is a view similar to FIG. 18 showing a subsequent stage in thefunctioning of the modified pulling probe as the probe releases from thesubassembly;

FIG. 20 is a view in section along the line 20--20 of FIG. 16;

FIG. 21 is a fragmentary longitudinal view in section of the head andbottom ends of a further modified form of running probe adapted to behydraulically actuated in the tubing string at any desired depth,showing the probe as run into the tubing;

FIG. 22 is a longitudinal view similar to FIG. 21 showing the modifiedrunning probe after it has been hydraulically actuated to release theprobe from the gas lift valves and latches supported on it;

FIG. 23 is a view similar to FIG. 22 showing only the upper end portionof the modified running probe after mechanically releasing the probefrom the gas lift valves and latches at the bottom of a tubing;

FIG. 24 is a. longitudinal view in elevation of a coupler used forconnecting together the power piston and sleeve shifting tools in thetool string;

FIG. 25 is a view of the coupler shown in FIG. 24 with its parts shiftedso that they are compressed together at one end for insertion into thecoupling recess of a well tool;

FIG. 26 is an enlarged exploded perspective view of the two principalparts of the coupler;

FIGS. 27 and 27a taken together illustrated in section and elevation asliding sleeve valve for use in the well system of FIG. 1, showing thevalve at its upper open position, and a sleeve valve shifting tooldisposed in the sleeve valve for moving the valve downwardly to a closedposition;

FIG. 27 shows upper portions of the sleeve valve and the sleeve shiftingtool;

FIG. 27A shows lower portions of the sleeve valve and sleeve shiftingtool and a fragment of the coupling of FIGS. 2426 connected into thelower end of the sleeve shifting tool; and

FIG. 28 is a view similar to FIGS. 27 and 27A showing a lower portion ofthe sliding sleeve valve at a closed position with a sleeve shiftingtool for moving the sleeve valve upwardly to an open position.

Referring to FIGS. 1, 2, and 13, a preferred form of tool string 30embodying the invention includes a pumpable power piston 31 for drivingthe tool string through a tubing during both well tool installation andretrieval. The piston is connected by a coupler 32 to a sleeve shifter33 for moving sliding sleeve valves in a well tubing string from lowerto upper positions. The sleeve shifter 33 is secured by another coupler32 to a sleeve shifter 34 for moving the sliding sleeve valves from anupper to a lower position. A running probe 35 is connected by anothercoupler 32 to the sleeve shifter 34 for supporting well tools andlatches during the installation procedure in the well tubing. An upperlatch and gas lift valve 41 and a lower latch 40a and lower gas l ftvalve 41a are releasably supported on the running probe for installationin a well tubing.

A well system in which the tool string 30 is useful for the installationof well tools, FIG. 1, includes a well 50a having a casing '51 providedwith a well head 52 through which a pair of strings of well tubing 53and 54 are supported in sealed relationship for conduc ing well fluidsfrom the well and directing well servicing fluids into and out of thewell. The casing may extend through and be perforated at a producingearth formation, not shown. The tubing 53 extends through a suitableconventional packer 55 downwardly to the vicinity of the producingformation for flowing well fluids to the surface. A lateral conduitconnects the lower end of the tubing 54 with the tubing 53 forcommunicating the tubings when the tool string is to be pumped into orout of the well. A stop 61 is secured in the tubing 53 in the vicinityof the conduit 60 so that when the lower end of the tool s ring engagesthe stop the piston 31 is above the conduit '60. The tubings 53 and 54communicate at spaced intervals through crossover connections 62, 63,and 64. The tubings are selectively communicated and isolated from eachother by sliding sleeve valves located in the tubing string 53 at thecross-over connections -62, 63 and 64.

A surface installation 72 is connected with the surface ends of thetubings 53 and 54 for controlling the production of well fluids from thewell through either of the tubings and for selectively directing fluids,such as lift gas and tool string displacing fluids, into either of thetubings while receiving fluid returns through the other of the tubings.Thus, the surface installation provides both for the control of primarywell production and for effecting various well servicing and secondaryrecovery techniques in the well through the tubing strings and therelated cross-over connections and other apparatus. The tubing 53 mayinclude a standing valve, not shown, located below the conduit 60 toallow well fluids to rise from a producing formation into the tubings 53and 54 while preventing the backfiow of fluids, either well fluids orwell servicing fluids, into any of the well conduits below the standingvalve.

A pulling tool string embodying the invention is illustrated in FIG. 13and includes a power piston 31, a sleeve shifter 34 for moving thesliding sleeve valves and a pulling probe 81 for removal of well toolsfrom a locked relationship in a tubing of a well system. The pullingprobe comprises an elongated articulated tubular structure for releasingwell tools in a tubing and withdrawing the tools from the tubing.

In operation the tool string 30 is inserted into the surface end of thetubing 53 at the surface installation 72 which is adjusted to pumpdisplacing fluid, such as oil or water, through the tubing 53 of thewell system 50 and return to the surface installation through the tubing54. The tool string is pumped downwardly in the tubing 53 with thesleeve shifter 34 sequentially engaging and movingeach of the slidingsleeve valves 65 downwardly to their closed positions as the tool stringis pumped to the lower end of the tubing against the stop 61 partiallyreleasing the latches on the probe. When the tool string reaches thestop the direction of fluid flow in the well system is reversed from thesurface installation 72 to pump the tool string 30 upwardly on a returntrip in the tubing 53. The piston 31 and the sleeve shifting tool 33pass upwardly through the lowest sleeve valve 65. The sleeve shifter 33which engages and moves the sleeve valve upwardly to its open position.The upper latch 40 and gas lift valve 41 pass through the lower sleevevalve 65 and the lower latch 40a is then fully released from the probeand locked in the tubing at the locking recess L above the sleeve valve.Continued upward movement of the tool string withdraws the probe fromthe lower latch and gas lift valve and lifts the probe in the upperlatch and gas lift valve shifting the upper latch keys to anintermediate armed condition. The upper latch is lifted by the probeinto the next sleeve valve 65 which has been engaged by the sleeveshifter 34 and shifted open. The upper latch 40 and gas lift valve 41are then released from the probe and locked at the sleeve valve. Thetool string, after releasing all of the latch units and gas lift valvessupported on its running probe, is pumped back to the surfaceinstallation 72 where it is removed from the system so that further wellprocedures such as gas lift production may be carried out in the wellsystem.

When removal of the latches and gas lift valves from the well system 50is desired, the tool string 80 with its pulling probe 81 is insertedinto the tubing 53 at the surface installation and pumped through thetubing downwardly in the well. As the tool string arrives at the upperlatch and gas lift valve the pulling probe is inserted downwardlythrough the latch and gas lift valve releasing the latch from itslocking recess in the tubing. Continued pumping then forces the toolstring with the upper latch and gas lift valve on the pulling probedownwardly in the tubing until the tool string reaches the next latchand gas lift valve where the procedure is repeated with the latch andgas lift valve becoming engaged on the probe and forced downwardly withthe tool string. Each latch and gas lift valve assembly locked in thetubing is thus sequentially released and engaged on the pulling probe.After each latch and valve assembly is released and forced downwardly,the sleeve valve at which it had been locked is moved downwardly to aclosed position by the downshifter 34. The entire tool string includingall of the released latches and gas lift valves on the probe are forceddownwardly until the lower end of the probe engages the collar stop 61to cause the latches to be fully locked on the pulling probe. Fluid flowdirection is then reversed in the well system pumping the tool stringwith the pulling probe and latches and gas lift valves engaged thereonback to the surface installation where they are removed from the tubingstring.

The surface installation 72 schematically illustrated in FIG. 1 isexemplary of only one arrangement of conduits, valves, pumps, and thelike for controlling the production and servicing of a well system. Theinstallation may in the case of an offshore well be situated at a shorelocation perhaps as far as several miles from the actual location of thewell system 50. The tubing 53 at the surface installation is connectedthrough spaced valves 90 and 91 defining a lubricator tubing section 92for the loading and unloading of the tool strings 30 and 80. Similarly,the tubing 54 at the surface installation includes spaced valves 93 and94 which define a lubricator tubing section 95 in the tubing 54 whichsimilarly may be used for the insertion and removal of a tool stringsuch as the tool strings 30 and 80. The lubricator sections 92 and 95communicate through a conduit 100 which connects into the lubricatorsections near the valves 91 and 9-4, respectively, so that displacingfluid may be pumped into the lubricators for displacing the tool stringsfrom the lubricators through the tubing into the well system. Theconduit 100 is connected through a pair of spaced valves 101 and 102. Aconduit 103 is connected into the conduit 100 between the valves 101 and102. The conduit 103 leads to a reservoir tank 104 through a pump 105and includes a pair of spaced valves 110 and 111 located on oppositesides of the conduit 100. A return line 112 including a valve 113 leadsfrom the conduit 100 to the reservoir for returning fluids from thelubricator section 95 into the reservoir tank. The conduit 112 isconnected into the conduit 100 between the valve 102 and the connectionof the conduit 100 into the lubricator section 95. Similarly, a returnline 114 including a valve 115 is connected from the reservoir tank intothe conduit 100 at a location between the valve 101 and the lubricatorsection 92. The surface ends of the tubings 53 and 54 connected into thevalves 91 and 94, respectively, may lead to well fluid treatmentfacilities such as separators, storage tanks, and the like and, also,may be connected with other facilities such as means for pumping liftgas into the well system when the well is to be produced by such asecondary recovery method.

The well head 52 and the supporting and sealing connections at the wellhead for the tubings 53 and 54, may be any suitable standard apparatus.

A preferred form of the sleeve valves 65 in the tubing 53 is illustratedin FIGS. 27 and 27A.

The sleeve valve includes an upper sub 200 which is internally threadedat its upper end for connection with a section of tubing string aboveit. The sub is provided with the internal spaced recess L for receivinglocking keys on the latches 40 and 40a and with a reduced bore portion203 which receives a seal on the gas lift valves and also functions inholding the lower end portions of the sleeve shifting keys of the sleeveshifter 34 pivoted outwardly while shifting the sleeve valve downwardly.The upper sub is threaded at its lower end into the upper end of ahousing section 204 which is provided with a lateral port 205 forproviding flow communication into the crossover conduit 63 to the tubingstring 54. The lower end of the housing 204 is threaded on the upper endof a lower sub 210 which has an upper bore portion 211, a reduced middlebore or cam portion 212, an a lower bore portion 213 of a diameterintermediate that of the bore portions 211 and 212. An upwardly facingshoulder surface 214 is provided in the bore of the lower sub betweenthe upper bore portion 211 and intermediate bore portion 212.

The sleeve valve 65 is slidably disposed in the housing section formovement between an upper open position, FIGS. 27 and 27A, and a lowerclosed position, FIG. 28. Upward movement of the sleeve is limited byengagement of its upper end surface 215a with the lower end surface 200aof the upper sub. The sleeve has an upper bore portion 215b which islarger in diameter than the cam bore portion 203 of the upper sub. Aplurality of circumferentially spaced lateral ports 220 provided in thesleeve valve are alignable With the housing port 205 when the sleevevalve is at its upper position to provide flow communication between theinterior of the valve and the cross-over conduit 60. The sleeve outsidediameter is slightly reduced along the ports 220 to provide an annulusaround the sleeve for improved fluid distribution. Upper ring seal 221and lower ring seals 222 are disposed within internal annular recessesprovided in the housing 204 above and below the lateral port 205 forsealing between the sleeve valve and the housing. Intermediate its ends,at the lower end of the upper bore portion 215b the sleeve is providedwith an internal annular flange 230 providing an upwardly facingshoulder 231 and a downwardly facing shoulder 232 which are engageableby sleeve shifting keys on the shifting tools 33 and 34 for moving thesleeve in the housing. The sleeve valve has a lower end portion 215c ofreduced external diameter below the flange 230 which telescopes into theupper bore portion 211 of the lower sub 210 when the sleeve valve ismoved downwardly to its lower or closed position. When the sleeve valveis moved downwardly to its closed position the ports 220 are below theseal rings 222 so that there is no fluid flow communication between theexterior of the housing and the interior of the sleeve 215 through theport 205.

The lower end portion of the sleeve valve 215 has a plurality oflongitudinally extending circumferentially spaced lands 215d which haveupper shoulder surfaces 2152 effectively defining an external annularrecess 224 around the sleeve valve at the upper ends of the lands. Thelands are provided at their lower ends with down wardly and inwardlyslope surfaces 215 An internal annular recess 232 is provided in thehousing above the upper end of the lower sub 210, and an inwardly sprungdetent 233 in the form of a C ring is disposed in the recess 232 torestrain the sleeve 215 against sliding movement at both its upper openposition and its lower closed position so that it is not accidentallymoved. The downwardly facing shoulder surfaces 215; on the sleeve landsare engageable with the detent for restraining the sliding sleeveagainst downward movement, but when sufficient downward force is appliedto the sleeve the detent is spread and expanded outwardly into therecess 232a releasing the sleeve to move downwardly until the detentcontracts inwardly into the recess 224 at the upper end of the lands forreleasably restraining the sleeve at its lower position. An upward forceon the sleeve engages the shoulders 215e at the upper ends of the landswith the detent to cam it outwardly to release the sleeve for movementupwardly to its open position as shown in FIG. 27A.

The form of the tool string 30 shown in FIG. 2 includes the power piston31 Which is a pumpable seal unit movable along a flow conductorresponsive to a fluid pressure differential applied across the unit. Asuitable power piston which may be used for moving the tool string isillustrated and described in US. Pat. No. 3,318,605, issued to Norman F.Brown, May 9, 1967. The piston unit shown in the Brown patent ispumpable in either direction and thus may be connected into the toolstring 30 by engaging the coupling 32 in the swivel cap 23 shown in FIG.1 of the drawings of the Brown patent.

The coupler 32 is used to interconnect the several tools included in thetool string between the power piston 31 and the probe head 35 asindicated in FIG. 2 so that the tool string is a loosely coupled, fullyarticulated system which readily traverses curves in the tubings betweenthe surface installation and the bottom ends of the tubings in the well.The coupler is illustrated in detail in FIGS. 24- 26 showing its partsand their relative operational relationships. The coupler comprises amale member 120 and a female member 121 supported together by a coilspring 122. The male member is basically a half tubular structure havingend locking flanges 123 and 124 and spring retainer flanges 125 and 126spaced from each other and spaced inwardly from the end flanges. A maleflange section 128 is defined along each longitudinal edge of thecoupler member 120 between the end cam surfaces 129 and 130. The femalecoupler member 121 is a half tubular member similar to the male member120 and is provided with correspondingly positioned end locking flanges123a and 124a and spring flanges 125a and 126a. The longitudinal edgesof each female member is provided with a female recess 130 definedbetween sloping end cam surfaces 131 and 132 which are closer togetherthan the cam surfaces 129 and 130 on the male flanges of the male memberso that the recess 130' is shorter than the male flange portions 128.The male and female coupler members are held together by the spring 122which encircles the members and is confined between the flanges 125 and125a at one end of the members and the flanges 126 and 126a at the otherend of the members. In the absence of forced conditions moving one ofthe members relative to the other, such as by opposite forces acting onthe members or one of the members being held while the other issubjected to a longitudinal force, the members are held in alignment bythe spring as shown in FIG. 24. When aligned the members are parallel toeach other because the male flange portions 128 on the male memberextend beyond the ends of the female recesses 130 in the female memberso that the vertical longitudinal edges of the female member endwardlyof the recesses 130 lie against or engage the longitudinal edge surfacesof the male flange portions 128 thereby supporting the members parallelto each other. A normal running condition of the coupler is as shown inFIG. 24 at which positions of the members the flanged opposite endportions of the coupler are received in well tool locking recessescoupling the well tools together. For example, the flanged end portionsof one end of the coupler are received in the coupling recess 603 of therunning probe head, FIG. 3A, while the other flanged end portions of thecoupler are received in a similar coupling recess at the lower end ofthe sleeve shifting tool 34.

The end portions at either end of the coupler may be compressed togetherby longitudinal movement or displacement of one of the coupler members.As for example in FIG. 25, the male and female coupler members areshifted in opposite directions until the cam surfaces 129 on the maleflange portions 128 of the male coupler are below the cam surfaces 131at the upper end of the female recess 130 so that the upper end portionof the male flange portions are received within the upper end portionsof the female recesses. At these relative positions of the male andfemale members the upper end portions of the couplers are compressedtogether as shown in FIG. 25 thereby reducing the effective diameter ofthe flanged end portions of the coupler members at the flanges 123 and123a so that the compressed end of the coupler is insertable into thecoupling recess of one of the well tools. After insertion of thecompressed end of the coupler the members are released to relax allowingthe members to return to the relative positions of FIG. 24 so that theflanged end of the coupling which had been compressed is connected intothe coupling recess of the well tool. The other end of the coupler issimilarly connected into an end locking recess in another well tool. Amore detailed description of the coupler 32 is found in US. Pat. No.3,428,346 issued Feb. 18, 1969 to John V. Fredd.

The sleeve shifting tool 34 of FIGS. 27 and 27A is symmetrical in form,only half of the tool being shown in the drawings. The tool has amandrel 370 having an enlarged section 371 provided with a pair oflaterally spaced transversely extending slots 372 each of which has anupper portion 372a extending longitudinally substantially parallel withthe longitudinal axis of the mandrel and a lower downwardly and inwardlyextending portion 372b. Each of the slots 372 receives a transverselyextending pin 373 pivotally supporting one of the sleeve shifting keys321 in longitudinally slidable and pivotal relationship on the body. Theopposite end portions of the pivot pins'373 are each secured in acircumferentially arcuate key 321. The keys 321 fit in opposed pivotallysupported relationship along opposite sides of the mandrel 370 for bothpivotal and laterally expandable and retractable movement on the body.Each key has an upper internal recess 375 conforming generally to theshape of the section 371 on the body and sufficiently longer to providefor the necessary longitudinal movement of the key on the mandrel whichis required when each of the keys move downwardly and inwardly on themandrel. The keys are loosely fitted to permit pivotal and longitudinalmovement, Each key has a lower internal recess 379 for receiving a lowerexternal annular enlargement or cam member 380 on the mandrel. The lowerend of the recess 379 in each key is defined by an upwardly facing camsurface 381 which is engageable with the downwardly facing cam surface382 on the lower enlarged section 380 of the mandrel so that downwardforce is transmitted directly from the mandrel to the lower end portionof each of the keys. Like the upper recess 375 of each of the keys, thelower recess 379 is substantially longer than the section 380 to providefor the desired pivotal and longitudinal movement of each of the keysalong the mandrel. Each of the keys has an upper external boss 384providing an upwardly facing cam surface 385 and a downwardly facing camsurface 390, and a lower external boss 391 provided with an upper camsurface 392 and a lower cam surface 393. The cam surface 393 isengageable with the shoulder surface 231 of the sliding sleeve 215 formoving the sleeve downwardly. Additionally, the outer surface of each ofthe keys is relieved along a lower portion 321a to facilitate wobblingor pivoting the keys past obstructions in the tubing string and in theflow control device. Each key is somewhat thicker along an upper portion321]) above an external shoulder 321c to provide suflicient thicknessfor structural rigidity of the key along the internal recess 375.

The lower end of each key is V-shaped in section as defined by anupwardly and inwardly sloping inner surface 393a and the upwardly andoutwardly sloping cam surface 393.

A ring 400 is disposed on the mandrel 370= below the keys and issupported on a spring 401 which biases the ring upwardly against thelower ends of the keys. The upper face of the ring 400 is in the form ofa V-shaped groove 400a which is substantially complementary to the shapeof the lower ends of the keys, so that the upward force exerted by thering on the lower ends of the keys tends to cam the lower ends of thekeys inwardly toward the tool body. The slopes of the key end surfaces393 and the corresponding outer surface portion of the groove 400a inthe ring 400 is greater than the slopes of the engaging cam surface 382and the upwardly facing inner key cam surfaces 381 so that the neteffect of the upward force of the ring on the lower ends of the keys isto cam the lower end portions of the keys inwardly.

The lower end of the spring 401 is supported by an upwardly facingshoulder surface 402 on a lower connector socket 403 threaded on thelower end of the tool body 370 and locked in place by a pin 403a. Thesocket 403 functions to receive a coupler 32 for connecting the lowerend of the sleeve shifting tool to the running probe 35. An upperconnector socket 411 is threaded on the upper end of the mandrel 370 forconnecting a coupler 32 to the upper end of the tool in the pump-downtool string.

When the tool 34 is moving freely through a full diameter portion of thetubing string, the spring 401 holds the ring 400 fully in contact withor seated against the lower ends of the sleeve shifting keys so that thekeys are restrained at a substantially neutral position generallyparallel with the longitudinal axis of the tool body. At such positionthe internal cam surface 381 at the lower end of the lower recess 379 ineach key is biased against the downwardly facing cam surface 382 on thelower enlargement 380 of the tool mandrel 370 and the lower end surfaces393 and 393a are seated in the key groove 400a. The pivot pin 373 ofeach key is located in its slot 372 substantially as shown in FIG. 27,though the keys are parallel with the body as distinguished from pivotedoutwardly along their lower ends as in FIG. 27.

The tool 34 is moved downwardly in the tool string with its sleeveshifting keys 321 held at their neutral position by the ring 400, untilthe lower ends of the keys enter the restricted bore portion 203 at thelower end of the sub 200 of the first or uppermost sleeve valve 65.Above this restricted bore portion the internal diameter of the sub,with the exception of those portions along the locking recesses 201 and202, is the same as the full diameter of the tubing string above theflow control device so that the sleeve shifting keys remain at theirneutral position until their lower ends enter the restricted boreportion 203. The restricted bore portion cams the lower ends of the keysslightly inwardly pivoting the keys on the pins 373 so that the lowerend portions of the keys pass through the restricted bore portion intothe upper bore portion 215b of the sleeve valve 215. As soon as thelower key bosses 391 pass below the restricted bore portion 203, theupward force of the ring 400 against the keys returns the keys to theirneutral positions until the upper external bosses 384 on the keys arriveat the restricted bore portion 203. When the upper bosses 384 enter therestricted bore portion, the upper end portions of the keys are cammedinwardly, pivoting the keys on the pins 373 and moving the lower endportions of the keys outwardly. The substantial length of the keys belowthe support pins compared with the length of the keys above the pinsprovides for a relatively small amount of inward movement of the upperend portions of the keys to effect a substantial outward movement of thelower end portions of the keys as the keys pivot. The keys andcomponents of the sleeve valve are so relatively proportioned that theupper key bosses 384 enter the restricted bore portion 203 when thelower cam surfaces 293 on the keys are slightly above the cam surface231 of the sliding sleeve at the upper end of the internal annularflange 215. The tool continues downward movement until the keysurfaces393 engage the sleeve shoulder surface 231. Since the restrictedbore portion 203 of the sub 200 holds the upper end portions of the keysinwardly, the lower end portions of the keys are held outwardly andcannot move inwardly, so that further downward movement of the tool alsomoves the sleeve 215 downwardly. The downward force applied at the upperend of the mandrel 370 from the piston unit 31 is transmitted directlyfrom the lower cam surface 382 of the enlarged portion 380 of themandrel through the lower end portion of the keys to the sliding sleeveat its shoulder surface 231, so that the pins 373 function for pivotalsupport of the keys but do not transmit force between the keys and thetool mandrel.

As the sleeve valve 215 is forced downwardly in the housing 204, thedownwardly facing shoulder surfaces 215 on the lands 215d engage thedetent 233 expanding or spreading the ring outwardly releasing thesleeve for downward movement. The sleeve shifting tool continues toforce the sliding sleeve valve downwardly so long as the upper bosses384 of the keys are engaged with the restricted camming bore portion 203of the upper sub. At substantially the same time as the upper key bossespass downwardly from the camming bore, the detent 233 enters the upperrecess 224 on the lower end portion of the sleeve valve to hold thesleeve at its lower closed position. If the sleeve is forced downwardlyslightly beyond the position of alignment of the detent ring with therecess 224 12 the lower end of the sleeve will engage the upwardlyfacing stop shoulder surface 214 in the bore of the lower sub 210 toprevent any further downward movement of the sleeve.

As soon as the upper bosses 384 of the keys exit from the restrictedcamming bore portion 203, the lower end portions of the keys are free topivot inwardly. The upward force of the spring 401 acting on the ring400, coupled with the camming action of the shoulder surface 231 in thesliding sleeve against the lower outer end surfaces 343 of the keys,cams the lower ends of the keys inwardly as soon as the keys are free toswing or pivot, and the keys are disengaged from the surface 231 of thesliding sleeve, releasing the shifting tool to move downwardly in thetubing string.

The lower outer bosses 391 on the keys move through the internal boss orflange 230' of the sliding sleeve leaving the sleeve at its lowerposition as the shifting tool moves downwardly. When the upper bosses384 of the keys arrive at the boss 230, the lower bosses 391 aresubstantially below the restricted bore portion 212 of the lower sub sothat the keys are free to pivot on the pins 373 and the upper endportions of the keys are cammed inwardly until the upper bosses 384 passdownwardly through the sleeve bore 230. The keys continue to wobble,swing, or pivot sufficiently as the tool moves downwardly to fully clearthe flow control device, after which the keys are returned by the springbiased ring 400 to their neutral position, in which they remain as thetool moves down wardly in the tubing string until the next sleeve valveis reached.

The tool 34 is returnable to the surface through each of the sleevevalves without shifting the sleeves from their lower closed positions.As the tool passes upwardly through the sleeve valves the keys 321wobble or pivot on the pins 373 sufliciently for the keys to passthrOugh the various restrictions in the sleeve valve. If the keys 321encounter an obstruction in the tubing string or in any of the sleevevalves past which the keys cannot move by normal pivotal action on thepins 373, the keys are forced downwardly and inwardly by the obstructionas the pins 373 move into the lower end portions 37% of the pivot pinslots. The inward position of the keys provides additional lateralclearance around the tool for movement past the obstruction, as alreadydiscussed.

FIG. 28 illustrates the sleeve shifting tool 33 for moving the slidingsleeve 215 upwardly from its lower closed to its upper open position,thereby returning the sleeve valve to the position of FIGS. 27 and 27A.The up-shifting tool has a mandrel 501 provided with a central annularenlargement 502 which has a pair of laterally spaced transverse slots503 formed therein. Each slot has a central longitudinal portion 503aextending substantially parallel with the longitudinal axis of themandrel, an upwardly and inwardly inclined upper portion 503b, and adownwardly and inwardly inclined lower portion 5030. A pair ofoppositely positioned longitudinally extending sleeve shifting keys 504are each loosely swingably or pivotally supported on the mandrel by apivot pin 505 which passes through one of the slots 503 and is securedat its opposite ends in the arcuate key.

Each of the keys 504 has a lower internal arcuate recess 510 whichreceives a portion of the mandrel enlargement 502 and is somewhat longerthan the enlargement to permit longitudinal movement along the mandrel.Each of the keys also has an upper internal arcuate recess 511 whichreceives a cam ring 512 secured by a shear pin 513 on the mandrel fortransmitting force from the mandrel to the keys. The ring 512 has adownwardly and outwardly sloping shoulder upper surface 512a which isengageable with the downwardly facing sloping shoulder surface 511a ofeach key at the upper end of the upper key recess 511. The upper end ofeach of the keys has boss 524 formed with an outwardly facing upwardlyand inwardly sloping upper cam surface 514 and an inner downwardly andinwardly sloping end surface 515 providing a substantially V-shape tothe upper end of the key.

A ring 520 is movably disposed on the mandrel above the upper end of thekeys and biased downwardly by a spring 521 confined between the ring andan upper socket connector 540 for biasing the keys to a neutral positionin the same manner as the ring 400 in the downshifting tool 34. The ring520 has a lower V-shaped face defined by an inner downwardly andinwardly sloping surface 522 and an outer downwardly and outwardlysloping surface 523. The lower face of the ring is engageable with theV- shaped upper ends of the sleeve shifting keys for releasably holdingthe keys at a neutral position. Each of the keys also has at its lowerend a lower external boss 525. The outer surface of each of the keys isrelieved along an upper portion 530 between the bosses to providesufficient clearance for pivoting past the various restrictionsencountered in the tubing string and flow control devices. Each of thekeys is somewhat thickened along a lower portion 531 to providesufiicient material strength along the lower internal recess 510.

The upper socket connector 540 is threaded on the upper end portion ofthe mandrel 501 for receiving a coupling 32 to connect the upper end ofthe up-shifting tool to the down-shifting tool 33. The socket connector540 has a downwardly facing shoulder surface 542 engaged by the upperend of the spring 521 so that the spring for biasing the ring 520downwardly is confined between the shoulder and the upper face of thering 520. Similarly, a lower socket connector 543 is threaded on thelower end portion of the tool mandrel for receiving a coupler 32 forconnecting the lower end of the up-shifting tool into the running probe.

As the tool 33 is moved downwardly through the tubing string, the sleeveshifting keys 504 are held by the ring 520 in a neutral position inwhich they are substantially parallel with the tool mandrel, so long asthe tool is in normal diameter portions of the tubing string. When thetool reaches the uppermost sleeve valve and the keys enter therestricted cam bore portion 203 of the sleeve, the lower end portions ofthe keys are pivoted inwardly sufficiently to pass downwardly throughsuch restricted bore into the larger bore of the housing 204 below theupper sub. When the upper bosses 524 of the keys enter the restrictedcam bore portion 203 they are cammed inwardly, pivoting the lower endportions of the keys outwardly until the upper end portions of the keyspass below the restricted bore portion. If the sleeve valve'215 is atits lower position, the expanded lower end portions of the keys movefreely downwardly in the housing 204 and sleeve without engaging theshoulder 231 of the sleeve. Irrespective of the sleeve valve position,the tool moves downwardly through the sleeve valve with the shiftingkeys wobbling, swinging, or pivoting sufficiently to clear the variousrestrictions within the flow control device, including the inner flangeor boss 230 of the sleeve and the restricted bore portion 212 of thelower sub 210. If the keys encounter an obstruction beyond which theycannot pass by the normal pivotal or wobbling effect, the keys areforced upwardly on the tool mandrel with the pivot pins 505 movingupwardly in the slots 503 to enter the inwardly sloping slot upperportions 50312 and the keys are retracted inwardly toward each other toprovide additional clearance for the keys to pass beyond theobstruction.

Thus, the up-shifting tool passes through all the sleeve valve on itsdownward run without affecting the valve position. During upward travelthe tool moves the valve upwardly to a closed position. As the toolenters a flow control device from below, the upper end portions of thekeys enter the restricted bore cam portion 212 of the lower sub 210camming the upper ends of the keys slightly inwardly until they havemoved above the restricted bore portion and enter the lower end of thebore of the sliding sleeve 215. When the lower bosses 525 of the keysenter therestricted-bore portion 212, the lower ends of the keys arecammed inwardly to swing or pivot the keys on the pins 505, swinging theupper end portions of the keys laterally outwardly so that the outerupper end surfaces 514 of the upper bosses engage the lower shouldersurface 232 of the sliding sleeve. The outward movement of the upperends of the keys cams the ring 520 upwardly against the force of thespring 521. FIG. 28 illustrates the up-shift tool at about the positionat which it initially engages the shoulder 232 of the sleeve valve formoving the valve upwardly. The force applied to the mandrel of the toolfor moving the tool upwardly is transmitted from the mandrel through theshear pin 513 to the ring 512. The upper face 512a of the ring engagesthe inner downwardly facing surface 511a of each key, thereby applyingupward force to the upper end portions of each of the keys which is thentransmitted from the surface 514 of each of the keys to the internalshoulder surface 232 of the sliding sleeve. Thus, the upward forcenecessary to move the sleeve is not applied to the pivot pins 505.

As the sleeve valve moves upwardly the detent 233 is cammed outwardlyinto the recess 232 by the upper end surfaces 215e on the sleeve,releasing the sleeve for upward movement. The tool moves the valveupwardly until the bosses 525 .at the lower ends of the key emergeupwardly from the restricted bore cam portion 212, at which time thevalve is at its upper closed position and the detent 233 is contractedinwardly around the sleeve below the lower cam surfaces 215 on the lowerend portion of the lands 45d on the sleeve valve.

Since the lower bosses 525 on the keys have moved above the restrictedbore portion 212 the lower ends of the keys are free to expand slightly,allowing the keys to pivot so the upper end portioins of the keys swinginwardly due to the combined action of the spring biased ring 520 andthe shoulder surface 532 acting on the key surfaces 514. The keys arethus cammed inwardly back to their neutral positions. The sleeve is thusreleased at its upper closed position, with the tool continuing upwardlyand the sleeve valve shifting keys wobbling or pivoting to clear theremaining restricted bore portions of the flow control device.

If, when the keysengage the sleeve valve, the valve is stuck and cannotbe moved upwardly by the normal force employed with the operating toolstring, the shear pin 513 holding the ring 512 on the tool mandrel issheared. allowing the ring to move downwardly on the mandrel and therebyfreeing the sleeve shifting keys for downward movement to the extentpermitted by the engagement of the pivot pins 505 in the slots 503. Asthe keys are forced downwardly, the pins 505 enter the downwardly andinwardly sloping lower end portions 5030 of the slots, so that the keysare retracted inwardly to provide additional clearance for the keys tomove upwardly through the sleeve valve, leaving it at the position atwhich it is stuck.

The running probe 35, which supports a string of well tools such as thelatches and gas lift valves illustrated in FIG. 2 during installation ofthe latches and valves in a tubing, is shown in detail in FIGS. 3A3E.The probe is shown within the latches and gas lift valves supported onthe probe. The probe is an articulated assembly which readily bends totraverse curved portions of a flow conduit, such portions leading tounderwater wells equipped for pumpdown procedures may have curvedlengths designed on radii of approximately 5 feet or greater. Referringto FIG. 3A the probe has a head 600 which includes an upper end cap 601threaded into a housing 602. The cap has a coupling socket or upwardlyopening recess 603 for connection of the coupling. 32 to provide apivotal support for the head from the coupling. The housing 602 has aport 604 to permit free flow of liquid or gases into and out of thehousing to prevent any piston effect within the housing which mayinterfere with proper operation of the probe. The lower end portion 605of the probe head housing is reduced in diameter providing an internalshoulder 606 and adownwardly converging external arcuate surface 607. Anarticulated rod assembly 608 is loosely supported from the probe head onthe shoulder surface 606. The rod assembly has a tubular head 609,having an enlarged flange portion 610 which is supported on the shouldersurface 606 in the housing 602. An internal, flexible elongated rod 615extends throughout the length of the probe holding the rod assemblytogether while giving it suflicient flexibility to negotiate curveconduit portions in a pumpdown well system. The rod is a relativelyslender continuous member threaded along its upper end portion into nuts616 which support the rod from the rod head 610 as seen in FIG. 3A. Aplurality of tubular sections or probe sleeves 617 are supported inend-to-end array along the entire length of the rod 615. The sleeves aregenerally of substantially the same length with the exception of thosesuch as 617a, FIG. 3B, and 617b, FIG. 3C, which extend through the rigidsections of somewhat longer well tools. The lengths of the probe rodsleeves are gauged to align the joints between them at the jointsbetween adjacent well tools in the string or swivel joints betweensections of the tools. For example,;

in FIG. 3B it will be noted that the upper two sleeves 617 meet withinthe swivel connection between the lower end of the latch 40 and theupper end of the gas lift valve 41. A typical joint or engagementbetween abutting ends of the sleeves 617 is shown in the broken-awayview of the probe in the upper portion of FIG. 3B. The lower end of theuppermost sleeve 617 is provided with an upwardly and inwardlyconvergent arcuate internal annular surface 617" which is complementaryto and engages an upwardly and inwardly convergent external end surface617' on the adjacent or next downward sleeve 617 of the probe. Eachjoint between abutting sleeves of the probe on the rod 615 are formed inthe same manner as the one shown in FIG. 3B which permits the sleeves toconform generally to the rod 615 for supporting the various tools on theprobe as it traverses a curved section of a conduit. The probe sleeve617a, FIGS. 3B-3C, iS- substantially longer than the sleeve 617 as itextends through the valve section of the gas lift valve assembly 41. Theprobe sleeve 617b, FIG. 3C, is disposed during the running-in procedurethrough the lower latch 40a and is provided with a detent spring 618which is welded along an upper end portion in a recess 619 formedlongitudinally along the probe. The spring functions to limit upwardmovement of the latch on the probe after the latch has been released toits armed condition. As shown in FIG. 3D the probe sleeve 617b isreduced in diameter along a lower end portion providing a shoulder 617aand having a boss 617d spaced from the shoulder 6170. The shoulder 617aand the boss 617d serve release and locking functions during theinstallation of the latch in a tubing.

As shown in FIG. 3E the lower end portion of the probe rod 615 extendsinto a bottom probe sleeve 617a and is welded to the sleeve through aplurality of lateral hole 620. The sleeve 617e is solid along its lowerend portion below its connection with the rod 615 and is provided with alateral hole 621 for a shear pin for connection of the probe in thelower end of the string of latches and gas lift valves during therunning-in procedure, as discussed in more detail below.

The upper and lower latches 40 and 40a are identical in structure andfunction in all respects except for the features of the heads of themandrels of the latches. The upper latch 40 is designed at its head toengage the head of the running probe while the head of the lower latch40a is designed to be releasably supported from the lower end of thewell tool immediately above it on the running probe. The principalcharacteristics of the latches will be described in terms of and byreference to FIGS. 3C, 3D, and 47. The main parts of both latches arebest visualized and understood by reference to FIG. 6. The latches 40and 40a each include a tubular body or sleeve-like housing 621 aninternal operator sleeve 622, operator lugs 623 and 623a, and locatingand locking lkeys 624. The upper latch 40 has an internal mandrel 625supporting the operator sleeve, lugs, keys, and housing while theseparts of the lower latch 40a are mounted on a mandrel 625a which isidentical to the mandrel 625 in all respects except at its head end. Themandrel 625 has a flared head 626, provided with an internal arcuatesurface 630 en gaged by the arcuate surface 607 on the head of therunning probe, FIG. 3A when installing a string of tools in a tubingwith the probe. The mandrel 625a of the lower latch, FIG. 3C has a head626a having an internal upwardly opening coupling recess 631 whichreceives a collet '632 used to secure the lower latch to the lower endof the upper gas lift valve. The head of the mandrel 625a also has acounterbore portion 6310 which receives the detent spring 618 forholding the lower latch against moving upwardly at an intermediate stagein the installation of the latches in a tubing as discussed below. Inall other respects, the mandrels of the upper and lower latches areidentical in structure and function. In a tool string using more thantwo latch-gas lift valve combinations the top latch has the mandrel 625while all of the other latches below include the mandrel 625a since theyare each connected to a well tool immediately above as distinguishedfrom the top latch which engages the running probe head.

The latch housing 621 has an upper operating lug recess 633, anintermediate lug recess 634, and a lower lug recess 635 spaced along thebody and separated by an upper internal locking surface 636 and a lowerlooking surface 637.

The operator sleeve 622 has a lower tubular portion 638 of uniformdiameter provided with a pair of upper oppositely positioned rectangularwindows 639 for the upper lugs 623 and a pair of opposite lower windows639a for the lower lugs 623a. The illustrated positions of the windowsand lugs disposed therein have been revolved in FIGS. 3D, 8A, 10B and 11for purposes of clarity in illustration and description. The windows 639and 639a may be located either as illustrated in FIG. 6 or revolved 90as in the other figures. It is preferred that the FIG. 6 positioning beemployed to maximize the structural strength of the operator sleeve 622.The upper portion 640 of the operator sleeve is enlarged in diameter andbifurcated to provide elongate oppositely positioned windows 641circumferentially spaced from each other and 90 from the lug windows.Each of the windows 641 receives one of the locking keys 624 which areexpandable and contractable during the locking and release of the latchin the tubing. The windows 641 extend into the lower reduced diameterportion 638 of the sleeve as best seen in FIG. 6. The sleeve is providedwith two pairs of retracting and retainer flanges 642 disposed near thelower ends of and on opposite sides of each of the windows 641 forretaining the key 624 when at its expanded position relative to thesleeve and window. Each flange 642 has a tapered lower end face 642a forretracting and locking the lugs '624. Each of the retainer flanges 642for each window extends longitudinally of the sleeve and projectscircumferentially intothe window from the vertical face of the sleevedefining the longitudinal or vertical sides of the Window. The flanges642 for each of the windows provides balanced retaining means for thelocking key in the window. The lower end of each of the windows 641 isdefined by an upwardly and inwardly sloping cam surface 643' which isadapted to engage a similarly inclined lower end edge surface on the keyin the window during the expansion of the key to a locking position.

At the upper end of the operator sleeve 622 a pair of diagonallyoppositely disposed triangular shaped slots or recesses 644 are providedadjacent the upper ends of the windows 641. One recess 644 is disposedalong one side of one window 641 :while the other recess 644 is spacedl80 from the first recess and adjacent the upper end of the other sideof the opposite window 641. Each of the recesses 644 receives a portionof a locking key retainer formed on the heads of the mandrels 625 and625a. The upper end edge surface portions 645 of the operator sleeveeach extend circumferentially the width of the window 641 on that sideof the sleeve and slope upwardly and inwardly for performing a lockingkey expansion function. In actual construction practice the operatorsleeve 622 is machined so that from the lower end surfaces 643 definingthe lower ends of the windows 641 the sleeve is forked or bifurcated todefine the two oppositely disposed windows 641 and upper and inwardlyopening recess in which a ring 646 is welded providing the upperboundary surfaces of the window 641 by the lower edge surfaces of thering. The sleeve and ring are then milled to define the two recesses644. The inner diameter of the ring 646 is the same as the diameter ofthe remaining portion of the sleeve. Also, the ring is machined toprovide the width of the windows 641 tapered end surfaces 645. It willbe evident that other approaches to the construction of the operatorsleeve may be employed to form the novel shape of the upper end of thesleeve, the windows, and retainer flanges and related features shown inFIG. 6.

The locking keys 624 are identical and each provided with spaced outerbosses 650 and 651 which are contoured to conform to the shape of theparticular tubing locking recess at which it is desired the latch bereleased and locked. The shape of the locking bosses on the keys may bevaried for several latches to be run in a particular tubing so that thekeys of each latch will fit only a particular specified looking recesswhile passing all other recesses along the tubing. In this way it isknown exactly which locking recess. the latch will release from therunning probe and lock in. Each locking key has an arcuate inner surface652 corresponding to the outer surface configuration of the portion ofthe mandrels 625 and 625a within the keys as best seen in FIG. 5. Eachkey has an internal arcuate lateral recess 653 the upper end of which isdefined by a sloping cam. surface 654 which is engageable by the camsurface 645 on ring 646 of the operator sleeve 622 for expanding the keyduring the locking of the latch in a tubing. The portion 652a of theinner key surface 652 above the recess 653 is engaged by the ringportion 646 across the window 64-1 when the key is fully expanded forholding the key at its expanded position. Each key is provided alongopposite edges or sides with an outwardly opening longitudinal recess655 which receives the retainer flanges 642 when the key is in thewindow 641. The lower end of each side recess 655 is defined by a camsurface 656 which is engaged by the face 642a of the adjacent retainerflange 642 during the retraction of the locking keys and while holdingthe keys retracted. The positioning of the cam surfaces 656 at oppositesides of each of the keys near the lower end thereof provides balancedforces applied by the flanges 642 to the lower end of the key forsmoothly and evenly retracting the keys responsive to downward movementof the operator sleeve 622. Each of the keys has oppositely disposedside retainer flanges 657 which are engaged by the inner surfaces of theretainer flanges 642 of the operator sleeve to aid in holding the keyswhen they are in their fully expanded positions. The inner surfaces ofthe flanges 642 engage the outer surfaces of the key flanges 657. Thekey flanges project from the side surfaces 655 of the keys as seen inFIG. 6. Each of the locking keys has an upwardly and outwardly openingupper side recess 658 along one side of the upper end portion of the keywith a retainer ear 659 projecting from the side of the key near itsinner surface 652 for holding the upper end of each key in alignmentduring its expansion and contraction and while at any given positionrelative to the mandrel and operator sleeve. Each of the keys has anupper inwardly facing sloping end surface 660.

Both the mandrels 625 and 625a have a tubular body portion 661 providedwith oppositely disposed longitudinal windows 662 through which theinward portions of the operator lugs 623 and 623a project to engage thearticulated rod sleeves of the running and pulling probes. As best seenin FIG. 4, the longitudinal side edges 663 of the windows 662 areinwardly convergent so that the operator lugs may not move into themandrel when the pulling or running probe is not disposed through themandrel. The window side edges 663 engage the side edges of the operatorlugs loosely to limit the inward movement of the lugs while allowingthem to expand outwardly for movement of the operator sleeve 622 duringthe various steps of locking and releasing the latch. The operator lugsmust be free to move radially inwardly and outwardly from an inwardposition at which they are aligned with the locking surfaces 636 and 637within the body 621 and expanding positions at which their outerportions are received in the recesses 633, 634, and 635 of the housing621. The inward portions of the lugs must project through the windows662 suificiently to engage the running and pulling probes disposedthrough the latch during installation and retrieval of the latch.

The upper portion of the mandrels 625 and 62511 aligned within thelocking keys are undercut to provide arcuate longitudinal surfaces 664along opposite sides of the mandrel spaced circumferentially from thewindows 662 and corresponding in shape to the inner surfaces 652 and652a of the locking keys so that the locking keys may be slightlythicker and also may fully retract within the operator sleeve windows tothe positions illustrated in FIGS. 5 and 3C.

The mandrel surfaces 664 are cylindrical but on a larger radius than theother cylindrical surfaces of the mandrel. The head 664 of the mandrel625 is provided with the internal annular arcuate surface 630 at itsupper end and with a downwardly and inwardly convergent surface 665which is engaged by the upper end surfaces 660 of the locking keys. Apair of oppositely disposed retainer projections 666 spacedcircumferentially apart extend downwardly from the head 664 a shortdistance along the tubular portion of the mandrel, each provided with anupwardly and outwardly sloping recess 667 provided in the side face ofthe projection aligned to receive the locking ear 659 of the locking key624 disposed along the mandrel surface 664 adjacent to the projection.It willbe noted that each of the locking keys is provided with only onelocking ear 659 so that each of the projections 666 has a recess 667only in that side of the projection facing the adjacent locking key..The ear 659 is received in the recess 667 to hold the upper end of thelocking key at any position of expansion or contraction of the key andguide the key during expansion and contraction. The lower lato'h mandrel625a is identical other than having the coupling recess 631 instead ofthe arcuate end surface 630.

When the latches are assembled, the operator sleeve 622 istelescopedinto the housing 621 with the lower reduced diameter portion638 of the sleeve disposed within the body, the relative longitudinalpositions of the hous ing and sleeve depending upon the state ofcontraction or expansion of the looking keys. The mandrel, 625 in thecase of the upper latch, 625a in the lower latch, is telescopicallydisposed within the operator sleeve with its retainer 666 aligned withthe recesses 644 of the operator sleeve so that when the operator sleeveis forced upwardly on the mandrel the retainers enter the recesses 644of the sleeve. The lugs 623- and 623a are disposed through the mandrelwindows 663 and the operator sleeve Windows 639 and 6394: with theoutside portions of the lugs extending outwardly of the sleeve tocooperate with the recesses and locking surfaces within the housing 621while the inner portions of the operating lugs project inwardly of themandrel windows 663 to function with the running or pulling probe. Thelocking keys 624 are each positioned within an operator sleeve window641. The ears

